In the upstream oil and gas industry, there is a continued drive to minimize the costs of developing oil and gas fields, particularly those in deep waters where many of the most recent fields have been discovered. Several of these deepwater gas reservoirs have not been developed and remain commercially “stranded” (i.e. economically unviable).
The conventional approach to development of offshore gas reservoirs has been to process the oil and gas on a surface platform. Although the platform can be fixed to the seabed in shallow water, this is not viable in deeper waters where a floating surface facility is subsequently required.
Bringing high pressure gas from a deepwater subsea well up to a floating surface facility has proven to result in very large “mega-facilities” which are heavy, expensive and which tend to become uneconomic. This is due, in part, to the weight of high pressure gas risers which must be supported by the floating facility, high pressure gas piping, emergency shutdown (ESD) valves, processing vessels and safety systems.
Recent examples of “mega-facilities” include:
AreaPlatform/FieldTopsides WeightAustraliaChevron Wheatstone35,000 tonneAustraliaInpex Ichthys55,000 tonnes (potential to increase)NorwayStatoil's Aasta Haasten25,000 tonnes
Oil and gas emerges from a reservoir as a complex mixture of components including gas and hydrocarbon liquids as well as water and impurities such as nitrogen, carbon dioxide, mercaptans and hydrogen sulphide. Traditionally, this mixture was processed on the platform to remove impurities and separate gas and liquid phases. When deepwater subsea operations were first developed, it was not technically possible to perform these processing operations in a subsea environment and it was conventional practice to pipe the multiphase fluids to either a nearby facility or to shore for processing.
There is also considerable risk of hydrocarbon hydrate formation in these pipelines which operate at high pressures and ambient seawater temperature, where hydrocarbon-water hydrates can form at typically 22° C. or 23° C. at elevated pressure.
To prevent hydrate formation in pipelines, the industry has adopted several mitigation strategies including injection of chemicals such as glycol or monoethylene glycol (MEG), methanol or other low dosage hydrate inhibitors. Other mitigation strategies include pipeline insulation and application of various forms of heating such as direct electric heating (DEH) or other trace heating mechanisms.
These strategies proved very successful over short distance and moderate water depths. However, as the industry has moved to developments at greater depth or greater subsea tie-back distances, these mitigation strategies have proved increasingly expensive.
The Woodside operated Pluto pipeline, for example, completed in 2010 and operational in 2012, was the world's longest “water wet” pipeline at approximately 200 km in length. This pipelines transports mixtures of gas and water inhibited by MEG, at significant volumes at lower flowrates in particular. The significant cost of this strategy became fully appreciated once the design of the pipeline and the quantities of MEG that were required for operation became apparent.
Another risk of transporting “wet” gas, even with the use of hydrate inhibitors, in the presence of acid gas contaminants is corrosion to the inner surface of the gas pipeline. Accordingly, corrosion resistant materials are often used in pipelines, resulting in increased capital expenditure to mitigate this corrosion risk and ensure optimum pipeline lifespan and integrity.
The present invention seeks to overcome at least some of the aforementioned disadvantages.